This section is intended to introduce various aspects of the art, which may be associated with some embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The prediction or estimation of the mechanical behaviors of a rock formation is of great importance to the petroleum industry. Such estimations allow, for example, for the strength of the rock formation to be modeled and the failures within the rock layers of a hydrocarbon system to be predicted. Rock failures can take a variety of forms, such as compaction (analogous to compressing a sponge), brittle fracture (i.e., creation of faults), or ductile behavior (i.e., flowage such as salt flows, or distributed deformation). A basic understanding of a typical hydrocarbon system aids in the appreciation of such failures.
Referring now to the simplified diagram shown in FIG. 1, a typical hydrocarbon system 100 includes a variety of basic components. The most basic component is a source rock 102. All known source rock types are sedimentary; that is, they are formed by the deposit of sediment over millions of years. Various portions of the source rock 102 may be permeable based on their porosity. Like pores in a sponge, rock pores are typically filled with air, water, and/or organic materials 104. The organic material 104 typically comprises the remains of dead plants, animals, and micro-organisms that are trapped as the layers of sediment build up.
As more layers of sediment are piled on, the temperature and pressure of the source rock 102 rises. If the temperature and pressure reach appropriate levels, often referred to as thermal windows, the organic material 104 within the source rock 102 is transformed into hydrocarbons 106, such as, but not limited to, natural petroleum and natural gas.
In the depicted example, adjacent to the source rock 102 is a porous, permeable layer of rock called reservoir rock 108. At least some of the hydrocarbons 106 generated from the source rock 102 have a lower density than the water in the pores of the source rock 102. As a result, the hydrocarbons 106 tend to migrate, or float, upward from the source rock 102 and into the porous reservoir rock 108.
As further depicted in FIG. 1, a layer of impermeable rock is located above the reservoir rock 108. This impermeable rock is commonly referred to as seal rock 110. In order for hydrocarbons 106 to accumulate in the subsurface, a hydrocarbon trap 114 is required. The hydrocarbon trap 114 can take a variety of forms, such as, but not limited to, an arch or a pinch-out (i.e., taper) of the reservoir rock 108. The seal rock 110 and the trap 114 hold the hydrocarbons 106 in the reservoir rock 108 and inhibit the hydrocarbons 106 from migrating further towards the earth's surface 112.
As noted above, the various layers of rock within the hydrocarbon system 100 are susceptible to failure. However, some rock failures can be thought of as “good fractures” while other are thought of as “bad fractures”. When drilling a hydrocarbon production well, it is desirable to drill the well bore in such a way as to take advantage of existing fractures or potential fractures to enhance the permeability of the reservoir and increase the flow of hydrocarbons through the reservoir to the well. Such fractures are considered “good fractures.”
Conversely, if a fracture were to occur in the seal rock 110 creating trap 114, then the hydrocarbons 106 could be released from the trap 114 and allowed to migrate to the surface 112. This would be an example of a “bad fracture”. In another example, if the source rock 102 was relatively impermeable and a fracture happened to establish a fluid connection between the reservoir rock 108 and an aquifer 116, then water would migrate from the aquifer 116 into the pores of the reservoir rock 108. The migrated water could plug the pores of the reservoir rock 108 and make it difficult, if not to impossible, for the hydrocarbons 106 to flow through its pore structure up to the well head.
The current state of the art in geology allows prediction of certain rock constitutive behaviors such as failure, and thus prediction of fracture, by using estimates of (i) the various stresses existing at different depths and locations in the formation and (ii) the strength of the rock, which generally increases with depth. Estimates of the first-mentioned values, namely stress patterns in a rock formation, are typically a function of three variables: the weight of the overburden above the formation, the degree of “push” or “pull” that the formation experiences due to tectonic forces, and the mechanical properties of the formation and adjacent rock units.
One constraint to such a method of failure and fracture prediction is that it is not possible today to directly measure the values of the mechanical properties of the rock as they existed millions of years ago, as the rock was being transformed by compaction and other diagenetic processes. To address this constraint, present-day conditions of the rock are measured and by “working backwards” from that information, inferences can be drawn about the likely properties of the rock in the past.
A variety of generalized strategies for modeling ancient rock properties have been used to provide information for a fracture-prediction analysis. One approach makes use of a linear interpolation between (i) rock properties assumed to exist at the time of the rock's deposition or soon thereafter and (ii) properties measured or assumed at the present day. The interpolation is accomplished at the proportional geologic time interval that is being modeled.
Another approach is to assume that all rock properties, such as cohesion, internal angle of friction, consolidation pressure, etc., are a function of burial depth and compaction alone. In this approach, the estimation can be as simple as deriving a compaction history by numerically “stacking” layer upon layer and allowing gravity and the weight of the overlying layers to compress and densify the layer or layers of interest. This can also be calculated using a density profile with depth and computing the mean stress with which approximates the consolidation pressure.
Another approach is to measure present-day properties of the rocks of interest and to either use those values explicitly or modify those values for some time in the past. This technique could be described as an educated guesswork. Wholly ad hoc guesses have also been used.
None of these techniques provide a systematic and scientific way to estimate rock properties at some time in the past. Thus, there is a need for improvement in this field.